Technical Field
[0001] The present invention relates to methods for fracturing geological formations in
the region of hydrocarbon bearing zones in order to stimulate production of desired
hydrocarbon fluids. The present invention also relates to hydraulic fracturing fluids
which demonstrate improved rheological properties for delivering a proppant into fractures
in order to maintain them in a highly permeable condition for improved hydrocarbon
recovery. The invention further relates to methods for preparation and use of such
a fluid.
Background of Invention
[0002] Hydraulic fracturing of oil bearing formations has been practiced commercially for
many years. Conventional hydraulic fracturing techniques involve pumping a fluid at
a sufficiently high pressure and volumetric rate through a well hole lined with a
steel pipe and into a hydrocarbon bearing zone to cause cracks to form and propagate
within the surrounding geological formation. Although both oil-based and water-based
fracturing fluids are available, water-based fracturing fluids are generally more
economical, and they offer greater control over a broader range of physical properties
than oil-based fluids. Water-based fracturing fluids are now generally preferred by
the hydrocarbon retrieval industry. The following discussion and the present invention
is directed to water-based fracturing fluids.
[0003] Fracturing fluids generally contain several components. among the most important
components are a proppant, which is a granular solid material, and a gellant, which
controls rheological properties of the fracturing fluid. Proppants are typically chosen
from highly rounded natural silica sand and from ceramic materials such as alumina.
Alumina is preferred whenever compressive forces are expected to be high. Numerous
other additives found in fracturing fluids include pH buffers, surfactants, clay stabilizers,
biocides, and fluid-loss additives. Many of these specific chemicals used in the fracturing
process are described in
Chemicals in Petroleum Exploration and Production II, North American Report and Forecasts
to 1993, Colin A Houston and Associates, Inc., Mamaroneck, New York (1984).
[0004] A primary purpose of fracturing fluids is to distribute the proppant in cracks formed
and propagated during fracturing, causing them to remain open after the pressure is
released. Uniform distribution of proppant in cracks tends to greatly increase the
permeability of a geological formation, especially of a very tight formation, and
enable a greater recovery and higher flow rate of hydrocarbons contained within the
formation.
[0005] Exemplary fracturing fluids are disclosed in US Patent No. 4 067 389 (Savins), which
comprise an aqueous mixture of the reaction products of a microbial polysaccharide
(such as a Xanthan gum) and a galactomannan.
[0006] US Patent No. 4 250 044 (Hinkel) discloses other fracturing fluids which include
a water soluble or swellable polysaccharide thickening agent, and, as a breaker, a
persulphate plus a tertiary amine. This patent refers to the use of modified celluloses
which are water soluble, and to water soluble or water soluble polysaccharides.
[0007] Hydraulic fracturing has become a relatively predictable practice. The orientation
and lengths of cracks can, under certain circumstances, be substantially predetermined
and controlled. The
Petroleum Engineering handbook, H B Bradley, ed., Chapter 55 (1987) present a useful background discussion of hydraulic
fracturing.
[0008] While the term "gellant" is in common use in the hydrocarbon recovery industry in
connection with fracturing fluids, the term should not be taken literally to mean
that fracturing fluid gellants form conventional nonflowing gels. Fracturing fluid
gellants may be more appropriately classified as viscosifiers and rheology control
agents. A primary purpose of the gellant is to maintain the proppant in suspension
during fluid preparation, pumping, and distribution into the well hole and cracks
generated within a hydrocarbon bearing formation. Gellants therefore should function
under diverse shear conditions. For example, several hundred thousand liters of fracturing
fluid may be injected into a well at pumping rates as high as 7950 L/min. Ideally,
the viscosity of the fluid should be low during fluid mixing and pumping to minimize
the energy required during these operations. The viscosity should be high enough,
however, so that the proppant does not fall out of suspension and is delivered to
its desired location. High temperatures in hydrocarbon bearing zones further complicate
the rheological properties and requirements of fracturing fluids.
[0009] The hydrocarbon recovery industry generally employs fracturing fluids that exhibit
reduced viscosity as shear conditions increase. The relatively higher viscosity exhibited
at lower shear conditions helps to maintain the proppant in suspension, while lower
viscosity exhibited under higher shear conditions improves fracturing fluid flow rate
and distribution.
[0010] Fluid behavior characteristics of a fracturing fluid can be described by the following
equation:
where τ is the shear stress, K is the consistency index, γ is the shear rate, and
n is the fluid behavior index.
When the value of n is 1, the fluid is Newtonian; when the value of n is less than
1, the fluid is thixotropic; and when the value of n is greater than 1, the fluid
is dilatant. Thixotropic fluids having values of n around 0.4 to 0.8 are typically
preferred for fracturing fluids. Newtonian fluids do not generally carry proppant.
[0011] Gellants are usually based on water soluble derivatives of common polysaccharide
materials such as guar gum, cellulose, or xanthan. Hydroxypropyl guar (HPG) and carboxymethylhydroxypropyl
guar (CMHPG) are two common guar derivatives that are frequently employed as gellants.
Cellulosic materials commonly employed as gellants include hydroxyethyl cellulose,
carboxymethylhydroxyethyl cellulose, and hydroxypropylmethyl cellulose.
[0012] Well conditions, particularly well temperatures, have significant bearing on the
choice of gellant. Hydroxypropyl guar is most useful at lower temperatures, and carboxymethylhydroxethyl
cellulose is frequently employed under at higher temperature conditions. Hydroxyethyl
cellulose and xanthan have intermediate temperature tolerances.
[0013] Recovery from deeper wells that typically involves higher operating temperatures
presents challenges and requires greater control over the rheological properties of
fracturing fluids. In general, increasing the gellant concentration in the fracturing
fluid results in increased viscosity. Practical, economical, and operational considerations,
however, limit the amount of gellant that can be introduced to a fracturing fluid
to increase its viscosity. Additionally, excessive gellant polymer loading may result
in poor mixing efficiency and substantial frictional resistance. Crosslinking agents
have been employed to circumvent some of these gellant limitations.
[0014] Crosslinking agents are now conventionally used in fracturing fluids to modify their
rheological properties. Some crosslinking agents operate on a time-delayed basis to
increase the fluid viscosity at the bottom of a well, after the fluid has passed through
the great bulk of the well casing. Crosslinkers that are currently used include polyvalent
metal salts that form chelates, such as borates, aluminates, titanates, chromates,
and zirconates. Different crosslinkers exhibit different pH and temperature limitations
that affect their usefulness under certain fracturing conditions.
[0015] After the fracturing fluid has been distributed in the well and the associated fracture
formations, the non-proppant fracturing fluid residue is removed from the formation,
while the proppant remains distributed in the fractures. Oxidizing agents and enzymes
that attack the gellant are commonly used to hasten removal of the fracturing fluid
residue. Temperature conditions may be determinative of the gel-breaking mechanism
to be employed. For example, enzymes are useful at temperatures of up to about 50°C.
Oxidants such as sodium or ammonia persulfate and calcium or sodium hypochlorite are
useful at temperatures of up to about 80°C.
In situ well temperatures above about 135°C may be sufficient to cause gel breakdown as a
result of thermal degradation without the aid of a catalyst.
[0016] Although substantial research efforts have been devoted to developing hydraulic fracturing
fluids that exhibit the desired stability and rheological properties, the results
have not been entirely satisfactory. The present invention is therefore directed to
fracturing fluids that provide improved rheological properties and control under various
fracturing conditions.
[0017] The invention provides a hydraulic fracturing fluid composition comprising:
an aqueous transport medium;
a fracturing fluid gellant dispersed in said medium to raise the viscosity thereof;
and
proppant particles suspended in said medium containing said dispersed fracturing fluid
gellant,
characterised in that bacterial cellulose is also dispersed in said medium to
raise the viscosity thereof, said bacterial cellulose being produced by a cellulose
generating strain of the genus Acetobacter grown in an agitated culture, whereby the
settling rate of the proppant particles prior to and during transport into a drill
hole and fractured geologic formation is reduced.
[0018] The invention extends to a method of making such a hydraulic fracturing fluid.
[0019] The introduction of bacterially produced cellulose to hydraulic fracturing fluids
comprising conventional gellants confers several advantageous properties. In particular,
higher viscosities are achieved, apparently without concomitant increases in friction
under flow conditions. Additionally, fracturing fluids incorporating bacterially produced
cellulose exhibit substantially reduced proppant settling rates, even at fracturing
fluid viscosities equivalent to those achieved using only conventional gellants.
[0020] Bacterial cellulose also imparts significant advantages to crosslinked fracturing
fluids. These advantages include increased resistance to both temperature induced
thinning and physical shear,
substantial insensitivity to solvent salt concentration, and enhanced rehealing ability.
Bacterial cellulose even lowers the pH at which fracturing fluids can crosslink in
the presence of certain crosslinking agents.
[0021] Bacterial cellulose may be incorporated in fracturing fluids comprising conventional
gellants, including guar, hydroxypropyl guar, carboxymethylhydroxypropyl guar, xanthan,
hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, and hydroxypropylmethyl
cellulose. These gellants are generally present in concentrations of about 0.60 to
7.2 g/L of mixed fracturing fluid, and more commonly in amounts of about 2.4 to 6.0
g/L fracturing fluid. The improvement observed and attributed to the introduction
of bacterial cellulose requires relatively small amounts of bacterial cellulose; e.g.,
in the range of about 0.12 to 4.8 g/L of mixed fracturing fluid, and preferably in
the range of about 0.60 to 1.8 g/L of mixed fracturing fluid. Proppant is typically
introduced in amounts of about 120 to 960 g/L fracturing fluid. All concentrations
recited herein are measured on a dry weight basis unless otherwise indicated.
[0022] Bacterial cellulose suitable for use in methods and compositions of the present invention
includes cellulose produced by various species of
Acetobacter organisms. Bacterial cellulose is distinguishable from plant cellulose in that it
is a reticulated fibrillar material having very high surface area. It has very different
properties in this regard from purified, plant-derived cellulose, e.g., wood pulps.
The bacterial cellulose preferred for use in the methods and compositions of the present
invention is produced by a strain of the
Acetobacter bacterium that is resistant to mutation to non-cellulose producing types and is cultured
under agitated culture conditions.
[0023] The above-mentioned and additional features of the present invention and the manner
of obtaining them will become apparent, and the invention will be best understood
by reference to the following more detailed description read in conjunction with the
accompanying drawings.
Brief Description of the Drawings
[0024] Fig. 1 is a bar graph showing the viscosity and single grain sand settling rate of
HPG/BAC fracturing fluids containing from 0 to 16% KCl.
[0025] Figs. 2A and 2B are diagrammatic representations of experimental test results showing
proppant suspension in POLYBOR™ crosslinked fracturing fluids at pH 8.5 at 51.7°C.
The fracturing fluid depicted in Fig. 2B additionally comprises bacterial cellulose,
while the fracturing fluid depicted in Fig. 2A does not incorporate bacterial cellulose.
[0026] Figs. 3A and 3B are diagrammatic representations of experimental test results showing
proppant suspension in TYZOR™ 131, crosslinked fracturing fluids at 65.6°C. The fracturing
fluid depicted in Fig. 3B additionally comprises bacterial cellulose, while the fracturing
fluid represented by Fig. 3A does not incorporate bacterial cellulose.
Description of the Preferred Embodiments
[0027] Certain strains of microorganisms of the genus
Acetobacter produce large quantities of cellulose when they are grown under agitated culture
conditions.
Acetobacter is characteristically a gram-negative, rod-shaped aerobic bacterium. Its metabolism
is respiratory rather than fermentative.
[0028] Cellulose chains or fiber strands are synthesized at the bacterial surface at sites
external to the cell membrane during agitated culture conditions. The cellulose fiber
strands produced by these microorganisms, although chemically similar to cellulose
produced from wood pulp, differ in a number of important respects. An important difference
is that cellulose fiber strands produced under agitated culture conditions by
Acetobacter are about two orders of magnitude narrower, having diameters of about 0.10 to 0.20
microns, than typical wood pulp cellulose fibers. Characteristics of cellulose-producing
bacteria and preferred growth and agitated culture conditions are fully described
in U.S. Patent No. 4,863,565, entitled "Sheeted Products Formed From Reticulated Microbial
Cellulose."
[0029] Taxonomists have been unable to agree upon a consistent classification of the cellulose
producing species of
Acetobacter. For example, the cellulose producing microorganisms listed in the 15th Edition of
the Catalog of the American Type Culture Collection under accession numbers 10245,
10821, and 23769 are classified both as
Acetobacter aceti, subspecies
xylinum, and as
Acetobacter pasteurianus. For the purposes of the present invention, bacterial cellulose produced by any species
or variety of bacterium within the genus
Acetobacter that produces cellulose is suitable, and bacterial cellulose produced by any species
of the genus
Acetobacter under agitated cell culture conditions is preferred. The bacterial cellulose used
in the following specific examples was produced from a strain of
Acetobacter aceti var.
xylinum having properties similar to or grown as a subculture of ATCC Accession No. 53-263,
deposited September 13, 1985, under the terms of the Budapest Treaty. The bacteria
may be cultured under conditions similar to those described below.
[0030] The base medium preferred for use with cellulose-producing microbial cultures is
referred to as CSL medium. A suitable CSL medium comprises:
Ingredient |
Final Conc. (mM) |
(NH₄)₂SO₄ |
25 |
KH₂PO₄ |
7.3 |
MgSO₄ |
1.0 |
FeSO₄ |
0.013 |
CaCl₂ |
0.10 |
Na₂MoO₄ |
0.001 |
ZnSO₄ |
0.006 |
MnSO₄ |
0.006 |
CuSO₄ |
0.0002 |
Vitamin mix |
10 mL/L |
Carbon source |
As later specified |
Corn Steep liquor |
As later specified |
Antifoaming agent |
0.01% v/v |
The final pH of the medium is preferably about 5.0 ± 0.2.
[0031] A suitable vitamin mix may be formulated as follows:
Ingredient |
Conc. mg/L |
Inositol |
200 |
Niacin |
40 |
Pyridoxine HCl |
40 |
Thiamine HCl |
40 |
Ca Pantothenate |
20 |
Riboflavin |
20 |
p-Aminobenzoic acid |
20 |
Folic acid |
0.2 |
Biotin |
0.2 |
[0032] The carbon source generally comprises monosaccarides or mixtures thereof, such as
glucose and fructose, disaccharides such as sucrose, and mixtures of mono- and disaccarides.
The carbon source may also be supplied as a complex mixture of sugars, such as molasses
or plant biomass hydrolysates such as wood hydrolysate, straw, sorghum, and the like.
Other carbohydrate derivatives, such as mannitol and sorbitol may also serve as carbon
sources in culture media. The carbon source is typically provided in concentrations
of about 0.5% to about 7.0% (w/v). The final pH of the medium is about 5.0 ± 0.2.
[0033] Corn steep liquor, yeast extract, casein hydrolysate, ammonium salts or other nitrogen-rich
substances may be used as a general source of nitrogen, amino acids, minerals and
vitamins. Corn steep liquor is preferred, and suitable concentrations thereof range
from about 0.1% to about 10% (v/v). Cell culture media comprising about 5% (v/v) corn
steep liquor is supplemented during the fermentation run with additional aliquots
of corn steep liquor. Corn steep liquor varies in composition, depending upon the
supplier and mode of treatment. A product obtained as Lot E804 from Corn Products
Unit, CPC North America, Stockton, California, may be considered typical and has the
following composition:
Major Component |
% |
Solids |
43.8 |
Crude protein |
18.4 |
Fat |
0.5 |
Crude fiber |
0.1 |
Ash |
6.9 |
Calcium |
0.02 |
Phosphorus |
1.3 |
Nitrogen-free extract |
17.8 |
Non-protein nitrogen |
1.4 |
NaCl |
0.5 |
Potassium |
1.8 |
Reducing sugars (e.g. dextrose) |
2.9 |
Starch |
1.6 |
[0034] The bacteria were first multiplied as a preseed culture using CSL medium with 4%
(w/v) glucose as the carbon source and 5% (w/v) CSL. Cultures were grown in 100 mL
of the medium in a 750 mL Falcon #3028 tissue culture flask at 30°C for 48 hours.
The entire contents of the culture flask was blended and used to make a 5% (v/v) inoculum
of the seed culture. Preseeds were streaked on culture plates to check for homogeneity
and possible contamination. Seed cultures were grown in 400 mL of the above-described
medium in 2 L baffled flasks in a reciprocal shaker at 125 rpm at 30°C for two days.
Seed cultures were blended and streaked as before to check for contamination before
further use.
[0035] The following description is typical of laboratory scale production of bacterial
cellulose. However, the process has been scaled up for fermentors as large as 20,000
L and the bacterial cellulose used in the following examples has been produced in
this larger equipment. There is no discernable difference in the bacterial cellulose
product formed in laboratory and commercial-size reactors.
[0036] Bacterial cellulose was formed in a continuously stirred 14 L Chemap fermentor at
30°C and ambient pressure using an initial 12 L culture volume inoculated with 5%
(v/v) of the seed cultures. An initial glucose concentration of 32 g/L in the medium
was supplemented during the 72-hour fermentor run with an additional 143 g/L added
intermittently during the run. In similar fashion, the initial 2% (v/v) CSL concentration
was augmented by the addition of an amount equivalent to 2% by volume of the initial
volume at 32 hours and 59 hours. Cellulose concentration reached about 12.7 g/L during
the fermentation. Throughout the fermentation, dissolved oxygen was maintained at
about 30% air saturation.
[0037] Following fermentation, cellulose was dewatered. The remaining cellulose was extracted
with a basic solution at a pH of approximately 13 or higher at 60° for 2 hours. After
extraction, the cellulose was washed with deionized water to remove residual alkali
and bacterial cells. The purified microbially produced cellulose was maintained in
wet condition for further use. It will be clear to one of ordinary skill in the art
that various modifications may be made to the above-described methods of producing
bacterial cellulose. The bacterial cellulose produced under stirred or agitated culture
conditions as described above, (hereafter referred to as "BAC") has a microstructure
quite different from that produced by bacteria grown in conventional static cultures.
BAC is a reticulated product forming a substantially continuous, three-dimensional
network of branching, interconnected fiber strands.
[0038] The bacterial cellulose prepared as above by the agitated fermentation has filament
widths much smaller than softwood pulp fibers or cotton fiber. Typically these filaments
are about 0.05 to 0.20 microns in width with indefinite length due to the continuous
network structure. A softwood fiber averages about 30 microns in width and 2 to 5
mm in length while a cotton fiber is about half this width and about 25 mm long.
Example 1
Viscosity Characteristics Gellant/BAC Fracturing Fluids
[0039] The effect of adding BAC to hydraulic fracturing fluids was determined using two
different methods for measuring viscosity and at high and low shear rates. Low shear
viscosities are relevant during the fracture settling process, while higher shear
viscosity values reflect the environment during the pumping process.
[0040] In this set of experiments, the BAC was added in combination with several polymeric
fracturing fluid gellants, specifically hydroxypropyl guar (HPG), carboxymethylhydroxypropyl
guar (CMHPG), and hydroxyethyl cellulose (HEC). Ratios of gellant to BAC were varied
using 2.4 to 4.8 g/L of gellant to 0.60 to 1.8 g/L of BAC. Preferred ratios were 4.8
g of HPG and CMHPG, and 3.6 g of HEC, each with 1.2 g of BAC per liter of fluid. The
mixtures were prepared in a Waring Blender using water as a solvent and mixing for
20 minutes at a medium speed. BAC dispersions in water generally require shear energy
to build viscosity.
[0041] The viscosity of the resulting fluids under low shear conditions was measured using
a Brookfield Viscometer, Model RV, with a number 1 or 2 spindle at 0.3 rpm, approximating
a shear rate of <20 sec⁻¹. Brookfield Viscometers are available from Brookfield Engineering
Laboratories, Inc., Stoughton, Massachusetts. Measurements were made at temperatures
of 26.7° and 65.6°C. The experimental results are shown below in Table 1. The results
demonstrate that significantly higher viscosities are observed when BAC is added to
a fracturing fluid comprising HPG or CMHPG. The low temperature trial for the fracturing
fluid comprising HEC and BAC also demonstrated a relatively high viscosity.
Table 1
Fracturing Fluid |
g/L |
Temp., °C |
Viscosity mPa·s |
HPG |
4.8 |
26.7 |
390 |
HPG |
4.8 |
65.6 |
160 |
|
CMHPG |
4.8 |
26.7 |
250 |
CMHPG |
4.8 |
65.6 |
125 |
|
HPG+BAC |
4.8 + 1.2 |
26.7 |
1180 |
HPG+BAC |
4.8 + 1.2 |
65.6 |
640 |
|
CMHPG+BAC |
4.8 + 1.2 |
26.7 |
840 |
CMHPG+BAC |
4.8 + 1.2 |
65.6 |
620 |
|
HEC+BAC |
3.6 + 1.2 |
26.7 |
880 |
HEC+BAC |
3.6 + 1.2 |
65.6 |
150 |
[0042] In a second experiment designed to measure fracturing fluid viscosities under higher
shear conditions, fracturing fluid samples prepared as above were tested using a Fann
50 Viscometer with a standard bob rotating at 40, 80 and 120 rpm. Viscosities were
calculated at shear rates of 40, 170, and 511 sec⁻¹. Tests were conducted at 21.2°,
37.8°, 51.7°, and 65.6°C. The Fann Viscometer is available from Fann Instrument Co.,
Houston, Texas. The results are presented in Table 2 and indicate that BAC reduces
the apparent viscosity of fracturing fluids at higher shear rates. This is a desirable
property for fracturing fluids, since it provides reduced viscosity during mixing
and at high shear conditions during fracture formation.
Table 2
Fracturing Fluid |
g/L |
Temp., °C |
Viscosity (mPa·s) at Shear Rates of |
|
|
|
40/sec |
170/sec |
511/sec |
HPG |
4.8 |
21.2 |
140 |
63 |
35 |
|
|
57.7 |
101 |
50 |
29 |
|
|
65.6 |
81 |
43 |
27 |
|
HPG+BAC |
4.8 + 1.2 |
21.2 |
86 |
43 |
26 |
|
|
37.8 |
69 |
37 |
23 |
|
|
51.7 |
46 |
29 |
20 |
|
|
65.6 |
35 |
24 |
17 |
|
CMHPG |
4.8 |
21.2 |
108 |
51 |
29 |
|
|
51.7 |
83 |
43 |
25 |
|
CMHPG+BAC |
4.8 + 1.2 |
21.2 |
104 |
45 |
24 |
|
|
37.8 |
91 |
40 |
22 |
|
|
51.7 |
72 |
34 |
20 |
|
|
65.6 |
49 |
27 |
18 |
|
HEC+BAC |
3.6 + 1.2 |
21.2 |
51 |
25 |
18 |
|
|
37.8 |
18 |
15 |
11 |
|
|
51.7 |
5 |
8 |
10 |
Example 2
Proppant Transport Properties of Gellant/BAC Fracturing Fluids
[0043] The ability of gellant/BAC fracturing fluids to impede the settling of single sand
grains was used as a measure of the proppant transport properties of the fracturing
fluids made and studied in the previous example. Settling rates were measured using
20-25 mesh Jordan Northern White sand at 26.7° and 65.6°C. Jordan sand is supplied
by Unimin, New Canaan, Connecticut. The proppant settling apparatus consisted of a
graduated cylinder filled with the appropriate fracturing fluid suspension and placed
in a constant temperature bath. Single sand grains were placed in the cylinder and
observed until the settling velocity as measured in mm/min, was constant. Several
replicate tests were run at each condition. The results shown in Table 3 clearly indicate
that fracture fluids containing BAC exhibit negligible sand settling. Corresponding
fracturing fluids that did not contain BAC had very high settling rates, particularly
at the higher temperature.
Table 3
Fracturing Fluid |
g/L |
Temp., °C |
Single Grain Sand Settling mm/min |
HPG |
4.8 |
26.7 |
25 |
HPG |
4.8 |
65.6 |
250 |
|
CMHPG |
4.8 |
26.7 |
188 |
CMHPG |
4.8 |
65.6 |
231 |
|
HPG+BAC |
4.8 + 1.2 |
26.7 |
1.0 |
HPG+BAC |
4.8 + 1.2 |
65.6 |
1.1 |
|
CMHPG+BAC |
4.8 + 1.2 |
26.7 |
1.5 |
CMHPG+BAC |
4.8 + 1.2 |
65.6 |
3.3 |
|
HEC+BAC |
3.6 + 1.2 |
26.7 |
0.18 |
HEC+BAC |
3.6 + 1.2 |
65.6 |
0.83 |
Example 3
Breakdown Characteristics of Gellant/BAC Fracturing Fluids
[0044] Fracturing fluids should also display ease of breakdown of the gellant to facilitate
removal of the fracturing fluid residue after the proppant is in place. Gellant breakdown
facilitates fracture cleanup and resumption of oil and/or gas flow. Introduction of
oxidizers and enzymes are two of the most common methods employed for accomplishing
gellant breakdown.
[0045] Breakdown characteristics of gellant/BAC fracturing fluids comprising 4.8 g/L HPG
and CMHPG, respectively, with 1.2 g/L BAC were measured at temperatures of 37.8° and
65.6°C. The test procedure entailed mixing the relevant viscosity breakers with the
fracturing fluid in a Fann 35 cell, bringing the cell to temperature, and monitoring
the viscosity over a 24 hour time period.
[0046] In a first set of tests, calcium hypochlorite (65% available chlorine) was utilized
as an example of an oxidizing breaker. Conventional breakdown techniques require about
0.030 to 1.2 g/L calcium hypochlorite, most commonly in the neighborhood of about
0.060 to 0.12 g/L. The initial viscosities of the gellant/BAC fracturing fluids were
about 25 mPa·s. Effective breakage was seen within 1 hour at a hypochlorite level
of 0.12 g/L. A second set of tests was run using the enzyme CELLUCLAST™ available
from Novo Laboratories, Inc., Franklinton, North Carolina, at a concentration of 0.05
to 8 mL/L.
[0047] The target viscosity for the treated fluids,
i.e., the desired viscosity after breakdown, is as low as possible, and at least under
about 10 mPa·s. Data generated as a result of the oxidizer and enzymatic breakdown
tests are presented in Tables 4 and 5. The target viscosity was reached for all gellant/BAC
fracturing fluids in no longer than 6 hours.
Table 4
Temp. = 37.8°C |
Viscosity (mPa·s) |
|
Hypochlorite @ 0.12 g/L |
Celluclast @ 0.05 mL/L |
Time, hrs |
HPG/BAC |
CMHPG/BAC |
HPG/BAC |
CMHPG/BAC |
0 |
25 |
25 |
25 |
25 |
1 |
11 |
9 |
11 |
13 |
2 |
11 |
8 |
8 |
11 |
4 |
11 |
8 |
5 |
7 |
6 |
10 |
8 |
4 |
7 |
24 |
10 |
8 |
1 |
3 |
Table 5
Temp. = 65.6°C |
Viscosity (mPa·s) |
|
Hypochlorite @ 0.12 g/L |
Celluclast @ 0.05 mL/L |
Time, hrs |
HPG/BAC |
CMHPG/BAC |
HPG/BAC |
CMHPG/BAC |
0 |
25 |
25 |
25 |
25 |
1 |
6 |
4 |
3 |
5 |
2 |
6 |
4 |
1 |
3 |
4 |
6 |
4 |
1 |
3 |
6 |
5 |
3 |
1 |
1 |
24 |
4 |
3 |
1 |
1 |
Example 4
Temperature Stability of Gellant/BAC Fracturing Fluids.
[0048] Temperature sensitivity profiles were measured for fracturing fluids comprising 4.8
g/L HPG with and without 1.2 g/L BAC. The viscosity was measured using a Brookfield
Viscometer at 0.5 rpm at target temperatures of from about 20 to 87.8°C. Viscosity
measurements for the HPG fracturing fluid fell rapidly as the temperature increased.
Viscosity measurements for HPG/BAC fracturing fluid decreased initially until a temperature
of about 48.9°C was reached, and then appeared to level off at about 12,000 mPa°s.
Fracturing fluids having a viscosity of 12,000 mPa·s are acceptable and exhibit adequate
single grain sand settling rates.
Example 5
pH Stability of Gellant/BAC Fracturing Fluids
[0049] The pH of the fracturing fluids comprising 4.8 g/L HPG with and without 1.2 g/L BAC
was varied from 2 to 12 and the viscosity was measured at each pH using a Brookfield
Viscometer at 0.5 rpm. pH variations were found to have no significant impact on the
viscosity of the HPG fracturing fluids and only slightly increased viscosity of the
HPG/BAC fracturing fluids.
Example 6
Effect of Increasing Salt Concentration on Gellant/BAC Fracturing Fluids
[0050] The concentration of KCl in fracturing fluids comprising 4.8 g/L HPG with 1.2 g/L
BAC was varied from 0 to 16%. The Brookfield viscosities and single grain sand settling
rates were measured at specified salinity increments, as expressed by percentage potassium
chloride. The results of these experiments are shown in Fig. 1. The viscosity decreased
slightly as the KCl concentration approached about 8%, and then appeared to level
off. The sand settling rate increased slightly or remained level at higher potassium
chloride concentrations. Several mono-, di-, and tri-valent metal salts, such as chlorides
of Na, K, Ca, Fe(II), Fe(III), and A1(III) were used to make gellant/BAC fracturing
fluids. The viscosities of HPG/BAC fracturing fluids were not significantly affected
by metal salt concentrations of 4%. These results are significant because they demonstrate
that liquids having a high salinity, such as those present at well sites, can be used
to make the fracturing fluids.
Example 7
Sustained Temperature Stability and Fluid Behavior Index of Gellant/BAC Fracturing
Fluids
[0051] HPG fluids containing 6.0 g/L HPG and 0, 1.2, or 2.4 g/L BAC were subjected to 148.9°C
and a shear of 40 sec⁻¹ for 60 minutes. Tables 6 and 7, respectively, present the
viscosities and behavior index values of these fluids at 21.1°C before and after heating,
as well as at 15 minute intervals at 148.9°C. The values in Table 6 show that the
BAC containing fluids maintained significantly greater viscosity during extended heating
and physical shear and were able to reheal to a much greater extent than the nonBAC,
HPG control fluid.
Table 6
Temp. |
Time in Minutes |
Viscosity (mPa s) at HPG 6.0 g/L |
|
|
0 g/L BAC |
1.2 g/L BAC |
2.4 g/L BAC |
(21.1°C) |
-10 |
241 |
233 |
214 |
(148.9°C) |
0 |
38 |
72 |
87 |
(148.9°C) |
15 |
21 |
67 |
80 |
(148.9°C) |
30 |
18 |
61 |
65 |
(148.9°C) |
45 |
13 |
54 |
60 |
(148.9°C) |
60 |
12 |
58 |
53 |
(21.1°C) |
80 |
85 |
271 |
176 |
[0052] Table 7 shows that the BAC containing fluids exhibit a significantly lower n', demonstrating
that they have better thixotropic properties for hydraulic fracturing than the nonBAC,
HPG control fluid.
Table 7
Temp. |
Time in Minutes |
n' at HPG 6.0 g/L |
|
|
0 g/L BAC |
1.2 g/L BAC |
2.4 g/L BAC |
(21.1°C) |
-10 |
0.40 |
0.35 |
0.32 |
(148.9°C) |
0 |
0.78 |
0.55 |
0.42 |
(148.9°C) |
15 |
0.75 |
0.55 |
0.43 |
(148.9°C) |
30 |
0.74 |
0.57 |
0.46 |
(148.9°C) |
45 |
0.94 |
0.56 |
0.47 |
(148.9°C) |
60 |
0.97 |
0.49 |
0.45 |
(21.1°C) |
80 |
0.51 |
0.35 |
0.40 |
Example 8
Formation Fracture Simulation
[0053] Computer simulations were run on several gellant and gellant/BAC combination fracturing
fluids to estimate fracture geometry and production ratio increases. A titanate crosslinked
gellant fracturing fluid (HPG/Ti) was also investigated. The program used, FRACANAL,
takes into account fluid leakoff, temperature gradients in the well, rheology of the
fracturing fluid, pumping schedule, and expected pressures in the well. Results are
shown in Table 8.
[0054] BAC containing fracturing fluids show a much higher predicted production increase
than fracturing fluids that do not include BAC because the BAC containing fluids create
longer fractures and distribute proppant throughout most of the fracture zone.
Table 8
Fracturing Fluid g/L |
Created Length, m |
Propped Length, m |
Production Increase Ratio |
HPG 4.8 |
99 |
45 |
3.5 |
|
HPG/Ti 4.8/.6 |
80 |
233 |
3.1 |
|
HPG/BAC 4.8/1.2 |
30 |
395 |
6.7 |
|
CMHPG 4.8 |
127 |
283 |
3.8 |
|
MHPG/BAC 4.8/1.2 |
235 |
363 |
5.5 |
|
HEC/BAC 3.6/1.2 |
343 |
390 |
7.9 |
Example 9
Friction Simulation Tests
[0055] Flow friction simulation tests were conducted by circulating a hydraulic fracturing
fluid without proppant through a 6.1 m length of 9.5 mm diameter stainless steel tubing
using a Jaeco Intensifier pump. The pressure drop across the tubing loop was measured
at various pumping rates. These tests demonstrate that the addition of BAC to fracturing
fluids comprising conventional gellants results in a very significant reduction in
flow friction. Table 9 compares the percentage friction reduction of several fracturing
fluids containing BAC compared to the flow friction of pure water. In all cases a
60+% friction reduction was achieved by the gellant/BAC fracturing fluid containing
no additional friction reducers.
Table 9
Fracturing Fluid |
Friction Reduction, % |
4.8 g/L CMHPG + 1.2 g/L BAC |
68 |
3.6 g/L HEC + 1.2 g/L BAC |
62 |
1.8 g/L CMHEC + 0.6 g/L BAC |
61 |
4.8 g/L HPG + 1.2 g/L BAC |
60 |
Example 10
Viscosity Characteristics of Borate Crosslinked Gellant/BAC Fracturing Fluids
[0056] Gellant/BAC fracturing fluids were prepared using water as a solvent in a Waring
Blender run at medium speed for 15 minutes. A concentration of 0.48 g/L boric acid
was added and thoroughly mixed with the gellant/BAC mixture. The pH of the fracturing
fluid was adjusted to 10 with a solution of 3% sodium hydroxide. The viscosities of
the resulting gels were measured with a Brookfield Viscometer, Model RV, at 0.5 rpm,
at a shear rate of <20 sec⁻¹.
[0057] Table 10 shows the effect on viscosity of varying HPG/BAC ratios in borate crosslinked
fracturing fluids. Although the ratios of BAC to HPG were varied from 0.3 to 1.2 g/L
BAC to 2.4 to 6.0 g/L HPG, Table 10 presents results from a narrower range within
those concentrations. A preferred ratio of BAC to HPG was experimentally determined
to be about 0.6 g/L BAC to 3.6 g/L HPG.
[0058] The results presented in Table 10 show significantly increased viscosities for crosslinked
fracturing fluids containing BAC, compared to those that do not contain BAC. Similar
viscosity increases were found for crosslinked BAC fracturing fluids with the other
gellants tested. The results also show that equivalent or better viscosities can be
obtained at lower HPG levels by the addition of BAC. The viscosity was unmeasurable
when more than 0.6 g/L of boric acid was used.
Table 10
|
Viscosity (mPa·s) |
|
BAC (g/L) |
HPG (g/L) |
0 |
0.3 |
0.6 |
2.4 |
64,000 |
105,000 |
134,000 |
3.6 |
174,000 |
248,000 |
272,000 |
4.8 |
184,000 |
-- |
-- |
Example 11
Temperature Stability of Borate Crosslinked Gellant/BAC Fracturing Fluids
[0059] One of the limitations of conventional borate crosslinked fracturing fluids gels
is that desired viscosity properties and proppant transport abilities may be lost
as a result of modest increases in temperature. A borate crosslinked HPG fracturing
fluid, for example, typically loses its ability to suspend proppant at about 65.6°C.
Accordingly, the viscosity of a borate crosslinked HPG fracturing fluid was compared
to that of a borate crosslinked HPG/BAC fracturing fluid at temperatures between 23.9
and 85°C.
[0060] Fracturing fluids were prepared in the manner described above with concentrations
of 4.8 g/L HPG, with or without 1.2 g/L BAC, and 0.48 g/L boric acid. The fracturing
fluids were heated to 85°C and allowed to cool in a controlled temperature bath. Viscosities
were measured using a Brookfield Viscometer at 0.5 rpm.
[0061] The experimental results presented in Table 11 show that the addition of BAC to borate
crosslinked HPG fracturing fluids significantly extends the useful temperature range
of such fracturing fluids. The borate crosslinked fracturing fluids containing BAC
maintained useful levels of viscosity up to the test limit of 85°C.
Table 11
|
Viscosity (mPa·s) |
|
HPG + BAC |
HPG |
Temperature °C |
4.8 g/L + 1.2 g/L |
4.8 g/L |
25.6 |
264,000 |
49,000 |
30.6 |
180,000 |
37,800 |
37.8 |
224,000 |
-- |
48.9 |
120,000 |
8,200 |
61.1 |
180,000 |
4,600 |
74.4 |
48,000 |
-- |
85.0 |
17,600 |
780 |
Example 12
POLYBOR™ Crosslinked Fracturing Fluids
[0062] Most conventional borate crosslinked hydraulic fracturing fluids are effective only
above a pH of about 9.5. POLYBOR™, a borate crosslinking agent made by U.S. Borax
and Chemical Co., is reasonably soluble and can be used at a pH of about 8.5. POLYBOR™
has consequently been proposed as a crosslinking agent for soluble gellants, but it
generally exhibits poor crosslinking properties at pH 8.5 and does not yield a usable
gel.
[0063] Table 12 shows the viscosity of various POLYBOR™ crosslinked HPG/BAC fracturing fluids.
HPG and HPG/BAC fracturing fluids were prepared as described in earlier examples.
POLYBOR™ was added at a concentration of 0.6 g/L while mixing the fluids for an additional
minute. The viscosities of the resulting gels were measured with a Brookfield Viscometer,
Model RV, at 0.5 rpm, approximating a shear rate of <20 sec⁻¹.
[0064] Table 12 shows significantly increased viscosities for POLYBOR™ crosslinked HPG fracturing
fluids containing BAC. The viscosities obtained with BAC are of sufficient magnitude
to provide usable hydraulic fracturing gels at a lower pH than is currently practiced.
Table 12
POLYBOR™ Crosslinked HPG (g/L) |
Viscosity (mPa·s) |
|
BAC (g/L) |
|
0 |
0.3 |
0.6 |
2.4 |
180 |
4,780 |
5,120 |
3.6 |
1,160 |
20,600 |
28,000 |
4.8 |
6,440 |
34,600 |
67,000 |
[0065] POLYBOR™ crosslinked fracturing fluids comprising various concentrations of CMHPG
and Guar, respectively, with and without BAC were also prepared and measured to determine
their viscosity. The results were similar to those presented above, with POLYBOR™
crosslinked fracturing fluids containing BAC having significantly increased viscosities.
Example 13
Proppant Transport Properties of POLYBOR™ Crosslinked Fracturing Fluids
[0066] The POLYBOR™ crosslinked fracturing fluids described in Example 12 were tested to
measure their ability to retain proppant suspended under dynamic conditions. A hydraulic
fracturing shear simulation apparatus was designed to simulate both high shear pumped
flow down a well bore and lower shear flow into a fracture area. In a preferred example,
2.75 kL of fracturing fluid containing 4.2 g/L HPG, 2.4 g/L BAC, and 0.6 g/L POLYBOR™
in 2% KCl was mixed for 30 minutes in a 2.84 kL tank using a moyno pump and a gate
valve to create a 6.9 x 10⁵ Pa pressure drop. Proppant in the form of 20/40 mesh Jordan
sand was added at the end of the mixing period. After thorough mixing, the gel was
pumped at a rate of 95 L/minute through the hydraulic fracturing simulation apparatus.
[0067] The simulation apparatus was designed with two portions, a well hole shear simulator
and a formation temperature shear simulator. The well hole simulator included a length
of 914.4 m of 2.54 X 10⁻ m diameter coiled tubing and was connected to the formation
simulator, which included a length of 97.5 m of 2.54 X 10⁻ m diameter tubing immersed
in ethylene glycol heated to 51.7°C. The formation simulator emptied into a slot flow
device having dimensions 3.56 X 10⁻¹ m high and 6.1 m long, where the proppant settling
was measured under dynamic conditions. Half the length of the slot flow device was
8.5 X 10⁻³ m wide and the other half was 6.4 X 10⁻³ m wide. One side of the slot device
was constructed of plexiglass and overlaid by a grid, and the other side was constructed
of aluminum and had heaters to maintain temperature.
[0068] The dynamic proppant settling properties were determined by analysis of video tape
recordings of the proppant suspension in the slot flow device. Fig. 2A is a representation
of the slot flow device containing POLYBOR™ crosslinked HPG fracturing fluid. Fig.
2B is a representation of the slot flow device containing a POLYBOR™ crosslinked HPG/BAC
fracturing fluid. Figs. 2A and 2B show very graphically that the addition of BAC to
the POLYBOR™ crosslinked fracturing fluid significantly enhances proppant suspension
and inhibits proppant settling.
Example 14
Viscosity Characteristics of Zirconate Crosslinked Fracturing Fluids
[0069] Zirconate crosslinked fracturing fluids are typically employed in high temperature
wells. In general, zirconate crosslinked fracturing fluids are sensitive to down hole
pumping, and may be unable to reheal. Consequently, zirconate crosslinked fracturing
fluids substantially lose their ability to transport proppant. Experimental results
suggest that BAC may extend and augment the use of zirconates to crosslink water soluble
gellants.
[0070] Fracturing fluids having the following compositions were prepared: 2.4 to 4.8 g/L
HPG and 0 to 2% ZrO₂, with and without 0.3 to 1.2 g/L BAC. The crosslinking agent
was introduced in the form of zirconyl acetate, available from Magnesium Elektron,
Inc., Flemington, NJ. The viscosities of the zirconate crosslinked fracturing fluids
were measured using a Brookfield Viscometer at 0.5 rpm. The results are shown in Table
13.
Table 13
|
Viscosity (mPa·s) |
Percent ZrO₂ |
4.8 g/L HPG + 1.2 g/L BAC |
4.8 g/L HPG |
0.0 |
9,480 |
720 |
0.1 |
45,400 |
2,200 |
0.2 |
46,800 |
3,400 |
0.6 |
48,000 |
3,200 |
1.0 |
57,600 |
6,000 |
2.0 |
63,200 |
9,000 |
[0071] Based upon the experimental results shown in Table 13, the preferred zirconate concentration
is about 0.6%. Consistent with the other crosslinked fracturing fluids containing
BAC, zirconate crosslinked fracturing fluids containing BAC demonstrated significant,
and in some cases more than ten-fold, increases in viscosity over zirconate crosslinked
fracturing fluids that do not contain BAC. The viscosity measurements also indicate
that the addition of BAC permits the use of lower concentrations of zirconates. Other
zirconate compounds, such as sodium zirconium lactate or ammonium zirconyl carbonate
could be substituted.
Example 15
Shear Stability of Zirconate Crosslinked Fracturing Fluids
[0072] To demonstrate additional benefits of incorporating BAC into zirconate crosslinked
fracturing fluids, fracturing fluids comprising 0.6% ZrO₂ and 4.8 g/L HPG, with and
without 1.2 g/L BAC, were prepared as described above. Various fracturing fluid compositions
were then subjected to increasing periods of shear in a Waring Blender. The viscosity
was measured at the end of each shearing interval with a Brookfield Viscometer at
0.5 rpm. The viscosities shown in Table 14 demonstrate that the addition of BAC protects
zirconate crosslinked gels from shear damage and allows them to reheal.
Table 14
|
Viscosity (mPa·s) |
Shear Interval in minutes |
4.8 g/L HPG + 1.2 g/L BAC |
4.8 g/L HPG |
1 |
58,800 |
26,000 |
3 |
62,000 |
30,000 |
5 |
59,600 |
14,000 |
10 |
65,600 |
14,400 |
20 |
59,200 |
15,200 |
30 |
62,400 |
12,800 |
Example 16
Viscosity Characteristics and Shear Stability of Titanate Crosslinked Fracturing Fluids
[0073] Like zirconate crosslinked fracturing fluids, conventional titanate crosslinked fracturing
fluids are shear sensitive, frequently do not reheal, and may stop transporting proppant
efficiently under elevated shear conditions. Elaborate mixing schemes using delayed
crosslinking agents are generally employed to make effective titanate crosslinked
fracturing fluids. TYZOR™ 131 is a spontaneously crosslinking commercial titanate
compound made by DuPont. Fracturing fluids having concentrations of 2.4 to 6.0 g/L
gellant, 1 mL/L TYZOR™ 131, with and without 0.3 to 1.2 g/L BAC, were prepared and
their viscosities were measured. Consistent with other BAC crosslinked fluids, TYZOR™
131 crosslinked fracturing fluids comprising BAC demonstrated significantly higher
viscosities compared to TYZOR™ 131 crosslinked fracturing fluids that did not contain
BAC.
[0074] To demonstrate additional benefits of incorporating BAC into TYZOR™ 131 crosslinked
fracturing fluids, fracturing fluids comprising 1 mL/L TYZOR™ 131 and 4.8 g/L HPG,
with and without 1.2 g/L BAC, were prepared. Each fracturing fluid composition was
subjected to increasing shear intervals in a Waring Blender. The viscosity was measured
at the end of each shear interval with a Brookfield Viscometer at 0.5 rpm. The results
are presented in Table 15 and show that the addition of BAC inhibits shear damage,
preserving sufficient viscosity for the transport of proppant.
Table 15
|
Viscosity (mPa·s) |
Shear Interval in minutes |
4.8 g/L HPG + 1.2 g/L BAC |
4.8 g/L HPG |
1 |
280,000 |
250,000 |
3 |
104,000 |
64,000 |
5 |
82,000 |
58,400 |
10 |
73,000 |
61,000 |
20 |
56,000 |
26,800 |
30 |
56,800 |
26,000 |
Example 17
Proppant Transport Properties of Titanate Crosslinked Fracturing Fluids
[0075] The TYZOR™ 131 crosslinked fracturing fluids described in Example 16 were tested
for their ability to effectively retain proppant in suspension under dynamic conditions
using the hydraulic fracturing shear simulation apparatus described in Example 13.
One mL/L TYZOR™ 131 in 2% KCl was used.
[0076] Figs. 3A and 3B show the appearance of the slot flow device containing TYZOR™ 131
crosslinked HPG fracturing fluids, with and without BAC, at 65.6°C. Fig. 3A is a representation
of the slot flow device containing TYZOR™ 131 crosslinked fracturing fluid. Fig. 3B
is a representation of the slot flow device containing a TYZOR™ 131 crosslinked HPG/BAC
fracturing fluid. The addition of BAC to the TYZOR™ 131 crosslinked fracturing fluid
significantly inhibits the proppant from settling. The large chunks of material shown
in Fig. 3B are relatively more solidified gellant portions.
[0077] It will be readily apparent that many departures can be made from the embodiments
shown in the examples while still remaining within the general scope of the invention.
Thus, the invention should be considered as being limited only as it is defined in
the following claims.
1. Verfahren zum Anfertigen einer hydraulischen Spaltflüssigkeits-Zusammensetzung mit
folgenden Schritten:
es wird ein wäßriges Transportmedium bereitgestellt;
die Viskosität des Mediums wird durch Dispersion eines Spaltflüssigkeits-Gels darin
erhöht; und
es werden stützende Partikel in diesem Medium suspendiert, die dispergiertes Spaltflüssigkeits-Gel
enthalten,
dadurch gekennzeichnet, daß der Schritt der Erhöhung der Viskosität auch eine Dispersion
einer Bakterienzellulose in dem Medium einschließt, wobei die Rakterienzellulose durch
eine Zellulose erzeugt wird, die eine Formänderung der in einer aufgelockerten Kultur
gezüchteten Gattung Acetobacter generiert, wodurch die Absetzgeschwindigkeit der stützenden
Partikel vor und während des Transports in ein Bohrloch und die gespaltene geologische
Formation verringert wird.
2. Verfahren nach Anspruch 1, enthaltend den Schritt einer Addition und Aktivierung ausreichender
Beträge eines quervernetzenden Agens, um die Spaltflüssigkeit querzuvernetzen.
3. Verfahren nach Anspruch 1 oder 2, bei dem das Spaltflüssigkeits-Gel aus der aus Guar,
Hydroxypropyl-Guar, Carboxymethoxyhydroxypropyl-Guar, Xanthan, Hydroyethyl-Zellulose,
Carboxymehtylhydroxyethyl-Cellulose und Hydroxypropylmethyl-Zellulose sowie Mischungen
davon bestehenden Gruppe ausgewählt wird.
4. Hyddraulische Spaltflüssigkeits-Zusammensetzung, enthaltend:
ein wäßriges Transportmedium;
ein in dem Medium dispergiertes Spaltflüssigkeits-Gel, um dessen Viskosität zu erhöhen;
und
supendierte stützende Partikel in dem das dispergierte Spaltenflüssigkeits-Gel enthaltenden
Medium,
dadurch gekennzeichnet, daß
Bakterienzellulose ebenso in dem Medium dispergiert ist, um dessen Viskosität zu erhöhen,
und daß die Bakterienzellulose durch eine Zellulose erzeugt wird,
die Formänderung der in einer aufgelockerten Kultur gezüchtetetn Gattung Acetobacter
generiert, wodurch die Absetzgeschwindigkeit der stützenden Parikel vor und während
des Transports in ein Bohrloch und gespaltete geologische Formation verringert wird.
5. Zusammensetzung nach Anspruch 4, zusätzlich enthaltend ein in der Mischung dispergiertes
quervernetzendes Agens, um die Spaltflüssigkeit querzuvernetzen.
6. Zusammensetzung nach Anspruch 5, in der das quervernetzende Agens aus einer Gruppe
ausgewählt ist, die aus Boraten, Zirkonaten, Titanaten, Aluminaten und Chromaten sowie
Mischungen davon besteht.
7. Zusammensetzung nach einem der Ansprüche 4 bis 6, bis der das Spaltflüssigkeits-Gel
aus der Gruppe ausgewählt ist, die aus Guar, Hydroxypropyl-Guar, Carboxymethoxyhydroxypropyl-Guar,
Xanthan, Hydroyethyl-Zellulose, Carboxymehtylhydroxyethyl-Cellulose und Hydroxypropylmethyl-Zellulose
sowie Mischungen davon besteht.
8. Verfahren zum Spalten einer geologischen Formation unter Verwendung einer hydraulischen
Spaltflüssigkeits-Zusammensetzung nach einem der Ansprüche 4 bis 7, enthaltend das
Bohren eines sich in die Formation hinein erstreckenden Bohrloches und die Übergabe
dieser Zusammensetzung in das Bohrloch und zu der Formation mit einer ausreichenden
Volumenrate und Druck, um ein Spalten zu verursachen und Brüche in der Formation auszulösen
und aufrechtzuerhalten.